When drilling into a reservoir, the drilling fluid containing bentonite is prone to solid phase invasion, causing serious damage to the reservoir, and the conventional API barite suspension stability is poor, which makes it easy to cause sedimentation and blockage. Therefore, in order to avoid accidents, we use ultrafine barite to obtain a good suspension stability. More importantly, the method of modifying zwitterionic polymers on the surface of nano-silica is used to develop a temperature-resistant and salt-resistant fluid loss reducer FATG with a core-shell structure, and it is applied to ultra-fine clay-free water-based drilling fluid (WBDF). The results show that the filtration loss of clay-free drilling fluid containing FATG can be reduced to 8.2 mL, and AV can be reduced to 22 mPa·s. Although the viscosity is reduced, FATG can reduce the filter loss by forming a dense mud cake. The clay-free drilling fluid system obtained by further adding sepiolite can reduce the filtration loss to 3.8 mL. After aging at 220 °C for 15 d, it still has significant salt tolerance, the filtration loss is only 9 mL, the viscosity does not change much, a thinner and denser mud cake is formed, and the viscosity coefficient of the mud cake is smaller. The linear expansion test and permeability recovery evaluation were carried out. The hydration expansion inhibition rate of bentonite can reach 72.5%, and the permeability recovery rate can reach 77.9%, which can meet the long-term drilling fluid circulation work in the actual drilling process. This study can provide guidance for technical research in related fields such as reservoir protection.

Efficient proppant transport in conglomerate reservoirs is severely constrained by rough fracture surfaces and strong geometric heterogeneity, leading to premature near-wellbore deposition and insufficient distal support. To address this challenge, this study aims to clarify the transport and deposition mechanisms of proppants in rough-wall fractures representative of the Mahu conglomerate reservoir. A large-scale visualized physical simulation system with an artificial rough fracture (20 m length × 4.5 m height) was developed based on dynamic similarity principles, enabling long-distance proppant transport observation under controlled pumping rate, fluid viscosity, proppant size, and sand concentration. Ten systematic experiments were conducted, and real-time particle motion and sand ridge evolution were captured using high-speed imaging and pressure monitoring. The results show that proppants form longitudinally layered sand ridges that evolve through three stages: leading-edge initiation, equilibrium-height growth, and distal extension. Viscosity and sand concentration primarily control propped-area continuity, while pumping rate governs transport distance and particle size affects structural stability. Rough fracture surfaces significantly intensify near-wellbore accumulation by enhancing energy dissipation and local flow heterogeneity. These findings provide mechanistic insights into proppant transport in rough fractures and offer quantitative guidance for optimizing fracturing parameters in conglomerate reservoirs.

Tight conglomerate reservoirs exhibit strong heterogeneity and complex stress–rock coupling. Hydraulic fractures form tortuous paths due to gravel interactions, complicating proppant migration and placement. Traditional smooth-plate models fail to capture real fracture features. This study uses large-scale true triaxial tests to generate fractures, three-dimensional (3D) scanning for digital reconstruction, and quantitative surface characterization. A Discrete Element Method-Computational Fluid Dynamics fluid–solid coupling model analyzes the effects of gravel content, proppant combinations, injection velocity, and branch fractures on proppant behavior. Results show: (1) Gravel-induced deflection/penetration increases roughness, raising proppant coverage by 8.99% and dune height by 15.61 mm, but hinders distal transport and accelerates settling; (2) mixed-size proppant causes “bridging;” a “small-to-large” sequence reduces blockage risk; (3) increasing injection velocity from 0.1 to 0.4 m/s cuts proppant coverage by 80.5% and dune height by 19.06 mm; near-wellbore filling suffers due to turbulence despite a longer migration distance; (4) branch fractures accelerate sedimentation and elevate the main fracture dune by approximately 8.85 mm, moderate velocity increases help; (5) mixed-size proppant improves sedimentation and packing; smaller particles (>50%) effectively fill voids. The proposed 3D reconstruction and multi-factor fluid–solid model offer theoretical guidance for optimizing fracturing in conglomerate reservoirs, enhancing conductivity and field performance.

Rough-walled fractures in conglomerate reservoirs promote near-wellbore proppant deposition, nonuniform flow, and insufficient distal support, making proppant-schedule screening difficult using small-scale smooth-slot tests alone. This study develops a benchmark-constrained and cost-aware hierarchical screening workflow by integrating a 20 m rough-wall physical experiment, transient Fluent simulations, and archived short-time EDEM sensitivity records. The benchmark experiment used a 20 m × 4.5 m × 10 mm artificial rough-wall fracture and ten operating conditions involving pumping rate, fluid viscosity, proppant size, and sand concentration. In the Fluent model, wall roughness was treated as a regularized roughness representation, and the carrier fluids were modeled using Newtonian constant viscosities measured from laboratory calibration. The experimental effective propped area ranged from 25.5% to 65.1%. Within single-factor comparison subsets, medium viscosity improved support continuity, pumping-rate gains became limited near 0.20 m³/min, particle size affected the balance between distal coverage and bed stability, and 300 kg/m³ sand concentration caused blockage. Image-segmentation-based comparison showed that Fluent captured the main wedge-shaped deposition morphology and screening-level geometric trends. The archived EDEM records indicated that grid-resolution refinement and mixed particle-size representation substantially increased computational cost. A Case 10 mesh-sensitivity check further confirmed that mesh refinement did not alter the first-order deposition morphology. The proposed workflow uses Fluent for whole-domain rapid screening and reserves EDEM/CFD-DEM for targeted short-time sensitivity checks.

Multi-stage multi-cluster hydraulic fracturing in conglomerate reservoirs is often characterized by strong cluster-to-cluster variability in fluid distribution, which can reduce stimulation efficiency. However, field-scale observations that constrain how injected fluid is partitioned among clusters remain limited, especially in strongly heterogeneous formations. In this study, wide-field electromagnetic (WFEM) monitoring was applied to a horizontal well completed in the Baikouquan Formation sandstone–conglomerate reservoir of the Mahu Sag, Junggar Basin. The monitored treatment consisted of 13 fracturing stages, each containing six perforation clusters. Time-lapse electromagnetic data acquired during pumping were inverted to reconstruct the spatiotemporal evolution of the effective conductive fluid-swept region. Based on the inversion results, we introduce a set of quantitative proxy indicators (swept area, swept length, cluster-specific sweep, and an asymmetric index) to support relative comparison of fluid distribution patterns at both stage and cluster scales. Results show pronounced non-uniformity within and between stages, even under similar pumping conditions. A limited number of clusters exhibit stronger and farther-reaching WFEM-inferred conductive-fluid responses, whereas other clusters show weaker or more localized responses. Asymmetric sweep patterns on opposite sides of the wellbore are also commonly observed. These patterns are consistent with the combined influences of reservoir heterogeneity, local structural/stress disturbances, and operational factors, although WFEM alone does not uniquely validate causal mechanisms of fracture growth. Overall, this study demonstrates that WFEM monitoring provides a field-scale proxy tool for delineating effective conductive fluid-swept regions and for evaluating cluster-to-cluster variability under consistent acquisition and inversion settings. The findings offer practical guidance for interpreting fluid distribution and optimizing multi-cluster fracturing in strongly heterogeneous unconventional reservoirs.